This invention relates to the recovery of petroleum from subterranean oil reservoirs. In particular, it relates to improved waterflooding operations involving the injection of a surfactant slug and drive fluid comprising concentrated brine.
In the recovery of oil from oil-bearing reservoirs, it usually is possible to recover only minor portions of the original oil in place by primary recovery methods which utilize only the natural forces present in the reservoir. A variety of supplemental recovery techniques has been employed in order to increase the recovery of oil from subterranean reservoirs. A widely used supplemental recovery technique is waterflooding, which involves the injection of aqueous media into the reservoir. As the water moves through the reservoir, it acts to displace oil therein to a production well system through which the oil is recovered.
Interfacial tension between the injected waterflooding medium and the reservoir oil, the relative mobilities of the reservoir oil and injected media, and the wettability characteristics of the rock surfaces within the reservoir are factors which influence the amount of oil recovered by waterflooding. Thus, it has been proposed to add surfactants to the flood water in order to lower the oil-water interfacial tension and/or alter the wettability characteristics of the reservoir rock. Viscosifiers such as polymeric thickening agents may be added to all or part of the injected water in order to decrease the mobility ratio between the injected water and oil and improve the sweep efficiency of the waterflood.
Techniques involving the injection of an aqueous solution of brine-tolerant surfactants have been developed for use under controlled conditions of salinity. Processes which involve the injection of aqueous surfactant solutions have been described in U.S. Pat. Nos. 3,508,612, 3,827,497, 3,890,239, 3,977,471 and 4,018,278, for instance. The surfactant slug may be followed by a thickened water slug which contains a viscosifier such as a water-soluble bipolymer in a graded concentration in order to provide a maximum viscosity greater than the effective viscosity of the flowing oil-water bank and a terminal viscosity near that of water. A driving fluid such as a field brine may be injected with or without the thickener to carry process to conclusion.
In the subterranean formation connate water may be present, often as a highly concentrated or saturated brine containing 10 to 20 weight percent sodium chloride, with smaller amounts of other soluble inorganic salts, especially Ca and Mg halides. The injected water customarily employed is oil field brine, which ordinarily contains at least 1% salt. By adding brine-tolerant surfactants to the available fluids, recovery of the petroleum can be enhanced. However, employing adequate surfactant to enhance the recovery of oil from the subterranean formation by the flooding water has not been economically feasible heretofore because the surfactants are absorbed from the surfactant solution onto the rock surfaces of the subterranean formation. As a result of this absorption of the surfactant, the concentration of the surfactant in the flooding water becomes less than that required to achieve enhanced recovery of the oil. Moreover, the adsorption, where the surfactant is a mixture, causes a chromatographic dispersion to separate components of the surfactant mixture on the basis of their relative sorptivity. Frequently, this dispersion destroys the efficacy of the surfactant mixture in lowering the interfacial tension between the flooding water and the oil being displaced within the formation.
Brine-tolerant surfactants are generally expensive chemical compositions, and less expensive sacrificial agents can be employed to prevent undue material losses. Alternatively, the saline surfactant solution may be followed by a less-saline water and flooding water, whereby the surfactant absorbed onto the formation surface from the initial surfactant slug is desorbed by the less-saline water. This latter technique is described in U.S. Pat. No. 3,474,864. Varying the composition of surfactant and brine drive fluids has also been disclosed in U.S. Pat. Nos. 3,346,047, 3,434,542 and 3,477,508. It is generally known in surfactant waterflooding technology to follow a relatively high saline surfactant slug with one of sharply-reduced salinity. Presence of a certain amount of salt prevents swelling and dispersion of clay materials in some formations. For instance, experimental Berea sand stone cores and many of the shaly-sand reservoirs in the Texas gulf coast region cannot tolerate water having a salinity below about 0.6% TDS, and this concentration may be a lower limit for practical water flooding operations in such formations if permeability damage is to be prevented. Ordinarily, the ambient saturation for NaCl defines a practical upper limit for brine salinity.
The fluid dose rate for surfactants, saline solutions, thickened drives, etc., can be expressed as a fraction of the pore volume (PV). This expression is commonly used to describe the void space in a natural geologic formation or a laboratory simulation, such as sand-packed tube. Progression of fluid through a formation is a slow process, being expressed in a few meters per day, or considerably less. When describing the treatment of a formation with 0.1 PV of surfactant slug, a period of days is usually implied, even for long tube scaled systems. Were a 10% equivalent pore volume to be injected in a natural formation, the linear rate might require months to inject.
For instance, certain connate waters having total dissolved solids (TDS) of 12 to 23 weight percent or more are found in natural formations, and are available for use as carriers or driving fluids. Pure water may be costly or obtainable in limited amount, requiring precise measures to be taken in conservation. It is known to drive a surfactant slug with successive fractional pore volumes of high-salinity brine, followed by a sharply-reduced concentration in the subsequent slug. It is believed that such drastic reduction in salinity contributes to reductions in reservoir permeability and/or to promotion of high emulsion viscosity, and results in higher operating pressures to maintain a constant linear flow rate in the formation.